Technical Field
This invention relates to hydrocarbon processing, and more particularly to systems and methods for efficiently upgrading heavy crude oil.
Background Information
Introduction to Heavy Crude Oil
The average weight or density of crude oils extracted from oil fields globally has been increasing very gradually over time, a trend expected to continue indefinitely. However, the existence of large reserves of heavy and extra-heavy crude oils in some countries means that the as-produced weight of crude oil can increase much more rapidly on a regional basis. Of particular importance are the tar oils in the Orinoco Belt in Venezuela and oil sand bitumen in Alberta, Canada, which in aggregate are currently estimated as being 2-3 times the size of the oil reserves in Saudi Arabia. The density of Saudi Arabian crude oils, expressed as API gravity or ° API, may typically fall in the range of about 27-34° API, in the center of which falls the current global average. By contrast, the deposits in Venezuela and Alberta are generally characterized as being heavy crude oils (HCO) or extra-heavy crude oils (EHCO) for which the corresponding densities may be regarded generally as being below about 22.3° API and about 10° API, respectively. (The lower the ° API value, the higher the density.) For deposits that are heavier still, such as in the case of some natural bitumen deposits in Alberta, the term ultra-heavy crude oil (UHCO) is sometimes applied. In most cases, the densities of native, unmodified heavy crude oils produced in Venezuela and Alberta are below about 15° API, and even below 10° API. (Though the classification scheme used herein to differentiate crude oils in terms of ° API will be recognized by those skilled in the art, other conventions and criteria exist, which may apply different terms and ° API ranges and/or include other criteria such as viscosity and percent sulfur. Therefore, definitions used herein should not be regarded as limiting but only illustrative.)
From the viewpoint of crude oil production and transport, HCO, EHCO, and UHCO, the entire group of which shall hereinafter be referred to inclusively as heavy crude oils (HCO) without limitation as regards exact composition or geological or geographic origin, are problematic because the same physico-chemical characteristics that cause their elevated density produce a corresponding increase in viscosity. By way of illustration that is neither bound by theory nor intended to be complete or applicable to all crude oils, asphaltenes are a class of diverse compounds known to affect density and viscosity directly and to have concentrations in HCO that are generally higher than in medium and light crudes. Having molecular weights that are high relative to other compounds in crude oils generally, increasing asphaltene concentration is generally accompanied by an increase in both density and viscosity. This may be due to the tendency of asphaltenes to self-associate, or it may be due to the formation of dense microscopic particles comprising a dense core of aggregated asphaltenes surrounded by layers of other crude oil components. Regardless of the mechanisms by which composition and microscopic structure cause elevated density and viscosity, HCO is generally not amenable to the methods of transportation and storage commonly applied to medium crude oils (about 22.3° API to about 31.1° API) and light crude oils (greater than about 31.1° API). For example, if crude oil were required to have a minimum ° API value of about 20 to be pipelineable, and if transport by rail tank car is precluded on the grounds of practical economics and logistics, then delivery to market of crude oil extracted from Albertan oil sands requires that it be somehow upgraded to meet pipeline specifications for density and viscosity.
Approaches to Upgrading Heavy Crude Oils
Commercially relevant upgrading strategies currently applied in Alberta fall into two general categories. In the first, coking, hydrocracking, or other techniques are applied to HCO to chemically convert asphaltenes and other heavy components into lighter materials, which are recovered through distillation and blended to produce pipeline quality synthetic crude oil. The various conversion and recovery processes are related to those employed in oil refining and the overall approach is correspondingly capital intensive, adding an estimated $14 per barrel. Furthermore, economic considerations preclude an implementation strategy whereby smaller-scale upgrading facilities may be located in or near numerous production fields.
Producers therefore rely on another, simpler strategy whereby the bitumen and heavy oil are mixed with higher-value, lighter petroleum products at the wellhead to produce diluted bitumen (dilbit) that can be easily transported through pipelines. However, several significant issues are associated with dilbit. First, the diluent must be transported by rail or pipeline to production fields from distant refineries or gas processing plants where it is produced. Second, dilbit in pipelines typically contains about 25% to 40% diluent, effectively reducing the net capacity of pipelines to carry unrefined crude. Compounding these issues, the net cost for diluent in terms of both the material itself and the facilities required to handle it adds $10-$16 per barrel of dilbit. However, beyond infrastructure and cost considerations looms a broader problem, namely, that diluent-based upgrading may not be a practical way to meet future growth of Canadian HCO production. Absent an alternative approach, Canada will be required to import ever increasing quantities of diluents. Currently, efforts are underway to expand the pipeline infrastructure from the Gulf Coast of the United Stated all the way to Alberta via Illinois to carry the “pentane plus” condensate by-product of shale gas production.
The need exists in the art for a new approach that requires lower initial capital investment, has lower ongoing operating costs, and combines the best features of the two main upgrading methods used currently: reduction of the density and viscosity of the native crude through conversion of asphaltenes and other heavy components into lighter ones; and scalability that permits distributed implementation at or near the wellhead to minimize or eliminate the reliance on diluent from remote sources.